The present invention relates to the field of oil and gas subsurface earth formation evaluation techniques and more particularly, to methods and systems for determining reservoir properties of subterranean formations using fracture-injection/falloff test methods.
Oil and gas hydrocarbons may occupy pore spaces in subterranean formations such as, for example, in sandstone earth formations. The pore spaces are often interconnected and have a certain permeability, which is a measure of the ability of the rock to transmit fluid flow. Evaluating the reservoir properties of a subterranean formation is desirable to determine whether a stimulation treatment is warranted and/or what type of stimulation treatment is warranted. For example, estimating the transmissibility of a layer or multiple layers in a subterranean formation can provide valuable information as to whether a subterranean layer or layers are desirable candidates for a fracturing treatment. Additionally, it may be desirable to establish a baseline of reservoir properties of the subterranean formation to which comparisons may be later made. In this way, later measurements during the life of the wellbore of reservoir properties such as transmissibility or stimulation effectiveness may be compared to initial baseline measurements.
Choosing a good candidate for stimulation may result in success, while choosing a poor candidate may result in economic failure. To select the best candidate for stimulation or restimulation, there are many parameters to be considered. Some important parameters for hydraulic fracturing include formation permeability, in-situ stress distribution, reservoir fluid viscosity, skin factor, transmissibility, and reservoir pressure.
Many conventional methods exist to evaluate reservoir properties of a subterranean formation, but as will be shown, these conventional methods have a variety of shortcomings, including a lack of desired accuracy and/or an inefficiency of the method resulting in methods that may be too time consuming.
Conventional pressure-transient testing, which includes drawdown, buildup, or injection/falloff tests, are common methods of evaluating reservoir properties prior to a stimulation treatment. However, the methods require long test times for accuracy. For example, reservoir properties interpreted from a conventional pressure buildup test typically require a lengthy drawdown period followed by a buildup period of a equal or longer duration with the total test time for a single layer extending for several days. Additionally, a conventional pressure-transient test in a low-permeability formation may require a small fracture or breakdown treatment prior to the test to insure good communication between the wellbore and formation. Consequently, in a wellbore containing multiple productive layers, weeks to months of isolated-layer testing can be required to evaluate all layers. For many wells, especially for wells with low permeability formations, the potential return does not justify this type of investment.
Another formation evaluation method uses nitrogen slug tests as a prefracture diagnostic test in low permeability reservoirs as disclosed by Jochen, J. E. et al., Quantifying Layered Reservoir Properties With a Novel Permeability Test, SPE 25864 (1993). This method describes a nitrogen injection test as a short small volume injection of nitrogen at a pressure less than the fracture initiation and propagation pressure followed by an extended pressure falloff period. The nitrogen slug test is analyzed using slug-test type curves and by history matching the injection and falloff pressure with a finite-difference reservoir simulator.
Conventional fracture-injection/falloff analysis techniques—before-closure pressure-transient as disclosed by Mayerhofer and Economides, Permeability Estimation From Fracture Calibration Treatments, SPE 26039 (1993), and after-closure analysis as disclosed by Gu, H. et al., Formation Permeability Determination Using Inpulse-Fracture Injection, SPE 25425 (1993)—allow only specific and small portions of the pressure decline during a fracture-injection/falloff sequence to be quantitatively analyzed. Before-closure data, which can extend from a few seconds to several hours, can be analyzed for permeability and fracture-face resistance, and after-closure data can be analyzed for reservoir transmissibility and average reservoir pressure provided pseudoradial flow is observed. In low permeability reservoirs, however, or when a relatively long fracture is created during an injection, an extended shut-in period—hours or possibly days—are typically required to observe pseudoradial flow. A quantitative transmissibility estimate from the after-closure pre-pseudoradial pressure falloff data, which represents the vast majority of the recorded pressure decline, is not possible with existing limiting-case theoretical models, because existing limiting-case models apply to only the before-closure falloff and the after-closure pressure falloff that includes the pseudoradial flow regime.
Thus, conventional methods to evaluate formation properties suffer from a variety of disadvantages including the lack of the ability to quantitatively determine the reservoir transmissibility, a lack of cost-effectiveness, computational inefficiency, and/or a lack of accuracy. Even among methods developed to quantitatively determine reservoir transmissibility, such methods may be impractical for evaluating formations having multiple layers such as, for example, low permeability stacked, lenticular reservoirs.